The NREL study examined two key questions, under models with high and low natural gas prices:

How might renewable energy deployment in the contiguous United States change
with these recent federal tax credit extensions?

How might this change in renewable energy deployment impact CO2
emissions in the power sector?

Under both sets of natural gas assumptions, the NREL study found that
tax credit extension scenarios
show
greater renewable
technology
investments through
the early 2020s
than scenarios without extensions:

The study found that scenarios
with
tax credit extensions also
show
lower
CO2
emissions
from
the U.S. electricity system:

Cumulative emissions reductions over a 15-year period (spanning
2016-2030) as a result of the tax credit extensions are estimated to range from
540 to 1,400 million metric tons CO2.

In all scenarios, nearly all of the
estimated growth in renewable energy capacity was primarily comprised of new solar and wind capacity, as opposed to biopower, geothermal, or hydropower technologies.

The NREL study concludes that tax credit extensions can have a "measurable impact" on
future renewable energy deployment and electric sector CO2
emissions
under a range of natural gas price
assumptions.

Friday, February 26, 2016

The Waterbury project is located at a dam built in 1938, and licensed for hydropower development since 1954. After a 16-year relicensing process, the Federal Energy Regulatory Commission issued a new license for the project in February 2016, authorizing 5.52 megawatts of generating capacity. That relicensing process illustrates how the Commission considers the need for power from the project, as well as project economics, when considering whether to relicense a hydropower project.

By regulation, the Commission's process for reviewing a license application includes an evaluation of the "need of the
applicant over the short and long term for the electricity generated by
the project or projects to serve its customers." In the Waterbury project's relicensing case, this consideration of the applicant's "need for power" involved observations about the project's expected output as well as the regional power market. The order notes historic average generation from the Waterbury Project of 17,562 MWh annually, but observes that under the new license average annual generation will be reduced to 14,767 MWh.

The order then states, "Electricity generated from the Waterbury Project will help supply the power needs in northern Vermont." It also cites a 10-year forecast by electric reliability organization North American Electric Reliability Corporation (NERC) showing summer peak demand in the region is expected to increase at an average rate of 0.84 percent per year between 2014 and 2023. Based on this, the order concludes that "the project's power will help meet the regional need for power."

The Commission's process for determining whether to issue a new license for an existing hydroelectric project also includes consideration of public interest factors, such as the economic benefits of project power. A 1995 decision established the Commission’s approach to evaluating the economics of hydropower projects. Under that approach, the Commission uses current costs to compare the costs of the project and likely alternative power with no forecasts concerning potential future inflation, escalation, or deflation beyond the license issuance date. The Commission has described the basic purpose of this economic analysis as to provide a general estimate of the potential power benefits and the costs of a project, and of reasonable alternatives to project power, "to support an informed decision concerning what is in the public interest with respect to a proposed license."

For the Waterbury project, as ultimately licensed with mandatory conditions and staff measures, the Commission concluded that:

the levelized annual cost of operating the project is $711,735, or $48.20/MWh

the proposed project would generate an average of 14,767 MWh of energy annually.

average generation is multiplied by the alternative power cost of $44.12/MWh, for a total value of the project’s power is $651,520, in 2015 dollars.

Therefore, the Commission concluded that in the first year of operation, the project would cost $60,215, or $4.08/MWh, more than the likely alternative cost of power. As the order notes, "Although staff’s analysis shows that the project as licensed herein would cost more to operate than the estimated cost of alternative power, it is the applicant who must decide whether to accept this license and any financial risk that entails."

The Commission did note that its consideration of public interest factors also considers that "hydroelectric projects offer unique operational benefits to the electric utility system", including ancillary services like stability and rapid response. The order also notes that while staff did not explicitly account for the effects inflation may have on the future cost of electricity, hydropower generation is relatively insensitive to inflation compared to fossil fueled generators -- illustrating why "project economics is only one of the many public interest factors the Commission considers in determining whether or not, and under what conditions, to issue a license."

Waterbury dam and reservoir were built by the United States in 1938 to reduce flooding in the Winooski Valley, but are owned by the State of Vermont and operated by Green Mountain Power. The Commission issued the original license for the project in 1954, effective September 1, 1951, for a period of 50 years.

That original license expired on August 31, 2001. Two years before that date, Green Mountain Power applied for a new license to continue operation and maintenance of the project. But relicensing a FERC-licensed hydropower project can be an involved process. Environmental, conservation, and recreation-oriented groups intervened in the application case. As the relicensing case progressed, the original license expired, after which Green Mountain Power operated the project under annual licenses pending the disposition of its license application.

In setting the 40-year license term for the Waterbury project's new license, the Commission noted its discretion under Section 15(e) of the Federal Power Act to issue new licenses for a term that the Commission determines to be in the public interest, but not less than 30 years or more than 50 years. The order also notes the Commission's general policy "to establish 30-year terms for projects with little or no redevelopment, new construction, new capacity, or environmental mitigation and enhancement measures; 40-year terms for projects with a moderate amount of such activities; and 50-year terms for projects with extensive measures."

The Waterbury project relicensing case illustrates one potential path for what happens when a license expires for an existing FERC-licensed hydropower project. According to the Commission, as of February 11, 2016, over 50 projects were pending relicensing, with an increase expected in applications for new licenses over the coming years.

At issue is Section 23(b) of the Federal Power Act. It provides that any person intending to construct project works on a non-navigable commerce clause water must file a declaration of their intention to do so with the Commission. Section 23(b) further provides that upon the filing of a Declaration of Intent, the Commission will investigate the proposed project, and, if it finds that the “interests of interstate or foreign commerce would be affected” by the proposed project, then the person intending to construct the project must obtain a Commission license before starting construction.

(a) is located on a navigable water of the United States;
(b) occupies lands or reservations of the United States;
(c) utilizes surplus water or waterpower from a government dam; or
(d) is located on a stream over which Congress has Commerce clause jurisdiction, is constructed or modified on or after August 26, 1935, and affects the interests of interstate or foreign commerce.

In the case of the Patton Colorado Hydropower Project, the Commission found that licensure is required under the fourth prong of Section 23(b)(1) of the Federal Power Act, which itself has three components.

First, the Commission found that the Patton project would be located on a "Commerce Clause stream." Specifically, the Commission found that Colombine Creek is a headwater or tributary of the South Fork of the Rio Grande, which is a tributary of the Rio Grande River, a navigable water of the United States. Under a 1965 Supreme Court precedent, for purposes of FPA section 23(b)(1), the headwaters and tributaries of navigable rivers are Commerce Clause streams.

Second, the project would be constructed after August 26, 1935.

Third, citing a 1992 opinion from the 11th Circuit Court of Appeals, the Commission noted, "It is well settled that small hydroelectric projects that are connected to the interstate grid affect interstate commerce by displacing power from the grid, and the cumulative effect of the national class of these small projects is significant for purposes of the FPA section 23(b)(1)." Thus the Commission concluded that the Patton Colorado Hydropower Project would affect interstate commerce through its connection to the interstate grid.

Based on these conclusions, the Commission found that in accordance with section 23(b)(1) of the Federal Power Act, the applicant must obtain a license for the construction, maintenance, and operation of the Patton Colorado Hydropower Project. The Commission also ruled that no construction or operation of the project may commence until a license has been obtained.

Notably, the Commission was able to reach this conclusion without making a navigability finding for Colombine Creek itself. In particular, the order notes "insufficient evidence to determine whether Colombine Creek is navigable." But because the Commission found licensing to be required on other grounds -- grounds derived from the ultimate navigability of a downstream river -- it did not make a navigability finding for the river reach where the project would be located.

Incentives and policy support for microhydro projects are growing. But as the Patton Colorado Hydropower Project case before the FERC illustrates, even small hydropower projects may be subject to federal regulation. For some projects, an exemption may be available, but others may not be able to be developed without a FERC license. Even an exemption can take time and expense to secure, and it can be hard to preduct the outcome of an application for an exemption. How does this dynamic affect the rate of development of U.S. micro-hydropower projects?

Tuesday, February 23, 2016

Federal energy regulators have issued an order issuing a successive preliminary permit to Cave Run Energy, LLC for a proposed hydroelectric project to be located at a dam in Kentucky owned by the U.S. Army Corps of Engineers.

The Federal Power Act provides for federal regulation of most hydropower projects in the U.S. Under Section 4(f) of the Federal Power Act, 16 U.S.C. § 797(f), the Federal Energy Regulatory Commission is authorized to issue preliminary permits for the purpose of enabling prospective applicants for a hydropower license to secure data and prepare material supporting a license application as required by section 9 of the Federal Power Act. As the Commission has said, "The purpose of a preliminary permit is to preserve the right of the permit holder to have the first priority in applying for a license for the project that is being studied."

After a public notice period, on February 11, 2016, the Commission issued a successive preliminary permit to Cave Run Energy for two more years. The order granting the successive preliminary permit notes the Commission's policy to "grant successive permits if it concludes that the applicant has diligently pursued the requirements of its prior permits." The order cites information provided by the applicant demonstrating progress with the analysis of the project’s feasibility, and towards the development of its proposed project, including the filing of a notice of intent and preapplication document.

As in some previous orders, the order granting Cave Run Energy a successive preliminary permit explains the Commission's reasoning in setting a two-year term for the successive permit. It notes that the Hydropower Regulatory Efficiency Act of 2013 authorizes the Commission to extend preliminary permit terms for not more than two additional years if the Commission finds that the permittee has carried out activities under the permit and with reasonable diligence. The order observes that this legislation suggests that "five years is a sufficient maximum period to prepare a development application." Accordingly, it granted Cave Run Energy a successive preliminary permit for a 24-month term.

Monday, February 22, 2016

NECA is New England's oldest and most broadly-based, non-profit trade association serving the competitive electric power industry. NECA facilitates an open forum among all electric power stakeholders to foster the development and maturation of competitive power markets.

NECA's 2016 Renewable Energy conference features panel discussions on hydropower imports, distribution network policy, reliability, transmission and storage, and emerging trends in renewable finance/economics. Of particular interest this year are state efforts to support large scale and distributed renewables like wind and solar, broad retirements of coal-fired and other central
generating power plants, proposed new infrastructure like electric transmission and natural gas pipelines, and shifts in the balance of resources New England relies upon for energy.

But the U.S. electric grid's energy mix is changing. In a Notice of Inquiry released on February 18, 2016, the Federal Energy Regulatory Commission notes that changes to the U.S. electric supply portfolio
likely mean that fewer resources are now primary frequency response. In particular, the U.S. has seen broad retirement of coal-fired baseload synchronous generators, some of which provide primary frequency response, while some have been replaced with variable energy resources such as wind and solar which do not
typically have primary frequency response capabilities.

In response, FERC solicited public input on whether and what action is needed, including whether to:

Amend the pro forma Large Generator and Small Generator
interconnection agreements to require that all new generation resources
have frequency response capabilities as a precondition of
interconnection;

FERC has docketed the matter as RM16-6-000, Essential Reliability Services and the Evolving Bulk-Power System — Primary Frequency Response. Comments on the Notice of Inquiry are due 60 days after publication in the Federal Register.

Friday, February 12, 2016

A Canadian company developing an oil sands mining and extraction project in Utah has announced a decision to "reduce the pace of field construction in order to maintain working capital flexibility," based on low oil prices.

Oil sands, also known as bituminous sands or "tar sands", are loose sand or partially
consolidated sandstone saturated with a viscous form of
petroleum called bitumen. US Oil Sands Inc. is a Calgary-based company that describes itself as "focused on oil sands exploration and production in Utah." Its wholly owned United States subsidiary US Oil Sands (Utah) Inc. has bitumen leases covering 32,005 acres of land in Utah’s Uinta Basin.

US Oil Sands' PR Spring Project area
consists of 5,930 contiguous acres near the East Tavaputs Plateau in
Utah. According to the company, construction of Phase 1 of the PR
Spring Project is approximately 85% complete with costs coming in below
budget. If completed, it would be the first U.S. oil sands mine to enter commercial production.

While the company has not yet entered production, US Oil Sands has described a proprietary extraction process using a citrus-based bio-solvent to extract bitumen from oil sands without the need for tailings ponds. The company pitched this technique as different from traditional Canadian oil sands production in Alberta, where wastewater management is a controversial environmental challenge. But the Utah proposal has drawn concern over impacts to groundwater flowing under the Book Cliffs

But the company said it conducted a detailed review of the project "in light of continued low oil prices and the closure of two key contractors’ Utah-based operations." Specifically, the press release stated, "The low price
environment has impacted the Project as two of the Company’s key
contractors have closed their operations in Utah and have caused delays
to the Project." Indeed, spot prices for West Texas Intermediate have ranged near $30 per barrel in recent days, with U.S. crude futures falling below $30 earlier this year for the first time since
2003. The press release also mentions that $10 million in previously-announced
royalty financing had not closed, causing the company to explore other
options including equity financing.

According to the press release, project work on the PR Spring Phase 1 project will continue at a reduced level, with an expected focus on "critical path items and areas that will lead to the most efficient
restart of full construction operations in the future. In spite of
delays and increased costs that will occur with restart of full
construction operations, the Company is still targeting completion
within the original US$60 million approved budget."

How will US Oil Sands survive the low oil price environment? How will economic, environmental, or other factors affect the fate of Utah oil sands mining?

Tuesday, February 9, 2016

The Supreme Court of the United States has issued an order staying the U.S. Environmental Protection Agency's Clean Power Plan regulations limiting carbon emissions from electric power plants. As a result, the rule's effect is frozen until legal challenges to the rule are resolved in federal court.

But numerous lawsuits have been filed challenging the rule, along with petitions to stay or freeze its effectiveness pending judicial review. Last month, the D.C. Circuit Court of Appeals denied petitions for stay from parties including states, utilities and trade groups such as the American Coalition for Clean Coal Electricity.

Parties then filed petitions for stay to the U.S. Supreme Court. Under a 2012 Supreme Court precedent, Maryland v. King, a party seeking a stay must demonstrate (1) a "reasonable probability" that the Supreme Court will
grant certiorari or agree to hear the case, (2) a "fair prospect" that the Court will
reverse the decision below, and (3) a "likelihood that irreparable harm [will] result from the denial of a stay." This is a relatively high burden.

The Environmental
Protection Agency’s "Carbon Pollution Emission Guidelines for
Existing Stationary Sources: Electric Utility Generating Units,"
80 Fed. Reg. 64,662 (October 23, 2015), is stayed pending
disposition of the applicant’s petition for review in the United
States Court of Appeals for the District of Columbia Circuit and
disposition of the applicant’s petition for a writ of certiorari,
if such writ is sought. If a writ of certiorari is sought and
the Court denies the petition, this order shall terminate
automatically. If the Court grants the petition for a writ of
certiorari, this order shall terminate when the Court enters its
judgment.

The order notes that Justice Ginsburg, Justice Breyer, Justice Sotomayor, and
Justice Kagan would deny the request to freeze the rule's effect. This note reveals a 5-4 decision to issue the stay, with Chief Justice Roberts, Justice Scalia, Justice Kennedy, Justice Thomas and Justice Alito in the majority as supporting the stay.

With the Clean Power Plan's effect stayed, litigation over the rule will now proceed in the U.S. Court of Appeals for the District of Columbia Circuit. The 27 states participating in challenges to the rule are likely cheering. Those include Alabama, Arizona, Arkansas, Colorado, Florida, Georgia, Indiana, Kansas,
Kentucky, Louisiana, Michigan, Mississippi, Missouri, Montana, Nebraska, New Jersey,
North Carolina, North Dakota, Ohio, Oklahoma, South Carolina, South Dakota, Texas, Utah, West Virginia, Wisconsin and
Wyoming. Meanwhile, the 18 states who filed in support of the EPA, along with those states who have started preparing compliance plans for the regulation, now find themselves on less certain footing. So too do electric power generators, and others interested in energy markets. If controversy persists, whatever decision the circuit court issues is likely to be appealed to the Supreme Court.

Maine Governor Paul LePage has released his 2016 State of the State remarks in the form of a letter to the state legislature. Among his top
priorities detailed in the letter is addressing the high cost of electricity in the manufacturing and industrial sectors. The eight-page letter also focuses on themes including welfare reform, lowering the income tax, reducing student debt and attracting youth, and fighting the drug crisis.

Energy issues appear in Governor LePage's letter as a focus for -- or obstacle to -- economic development. In the letter, he repeats his position that "Maine's electricity prices are not competitive." The letter criticizes legislative mandates supporting "long-term contracts for above-market rates" as adding $38 million in ratepayer costs.

The letter also addresses Maine's renewable energy policy, calling for support for Maine's biomass energy industry while criticizing the economics of wind and solar energy projects:

Socialists love to subsidize new wind and solar energy projects because they think it will save the earth,
but that kind of expensive and inefficient energy benefits only a few wealthy investors, and our
electrical generation is already one of the cleanest in the country. Instead, let's support the existing
Maine-based biomass infrastructure that is already in place to take advantage of our plentiful natural
resource: wood.

Meanwhile, my Administration continues to make progress working with other New England states to expand hydropower and natural gas into our region. Right now there is construction underway to expand our pipelines into New England, and clean and affordable hydropower is right next door in Quebec. It's time to switch off expensive energy. We must plug into the affordable reserves of nearby natural gas and hydropower. We must be willing to transmit hydropower to the states south of us.

These themes of energy infrastructure investment echo those playing out elsewhere in the Northeast U.S., as states explore expanded connections to natural gas from the Marcellus shale and Canadian hydropower.

FERC's Office of Energy Projects releases regular reports on energy infrastructure permitting and development. Its Energy Infrastructure Update for December 2015 presents a look at highlights of natural gas, nonfederal hydropower, electric generation, and electric transmission projects developed in the final month of 2015. The December report also provides a cumulative look at 2015 activity, along with comparisons to 2014.

According to the December 2015 report, solar accounted for the most generation units placed in service in 2015, with 248 projects. (The report only covers plants with nameplate capacity of 1 megawatt or greater, so smaller, distributed, behind-the-meter, or net-metered projects might not be counted here.) On the basis of megawatts of capacity installed in 2015, solar ranked third behind wind and natural gas.

Wind took second place in terms of number of projects placed in-service in 2015 with 69 listed "units", but took first place in terms of installed capacity with nearly 8 gigawatts placed in service last year.

Natural gas took third place in terms of both number of units installed (50) and megawatts of capacity added (nearly 6 gigawatts). Solar, wind, and natural gas together accounted for nearly 97% of all new capacity installed in the U.S. in 2015. Biomass and hydropower placed fourth and fifth, respectively, in both lists.

The report also shows a comparison to 2014, when new capacity installed was led by the same three generation types -- natural gas, wind, and solar.

The updated Comprehensive Energy Plan reaffirms Vermont's overall goal of
achieving 90 percent of its total energy needs from renewable sources by 2050, adds
interim goals (including reaffirming the statutory goal of 25% by 2025), and provides greater
detail on Vermont’s pathways towards achieving these goals. In particular, the plan includes the following new and more detailed goals:

Reduce total energy consumption per capita by 15% by 2025, and by more than one third
by 2050.

Meet 25% of the remaining energy need from renewable sources by 2025, 40% by 2
035,
and 90% by 2050.

Conversion of heat and transportation applications to "highly efficient electric technologies, such as heat pumps and electric vehicles," is one strategy highlighted in the plan. The plan also includes a 20-year electric plan, based on the principles of least-cost planning, that serves as a basis for Vermont electricity policy.

Friday, February 5, 2016

Suppose you own an existing water powered mill complex whose hydromechanical facilities have not been operational for decades. You would like to develop a hydropower project at the site, using the existing dam, headrace, and headgates, plus new equipment including two small generators, penstocks, and appurtenant facilities, to provide electricity to your home and workshop. Do you need a license from the Federal Energy Regulatory Commission?

Pursuant to section 23(b)(1) of the Federal Power Act, a non-federal hydroelectric project must be licensed (unless it has a still-valid pre-1920 federal permit) if it:

(a) is located on a navigable water of the United States;
(b) occupies lands or reservations of the United States;
(c) utilizes surplus water or waterpower from a government dam; or
(d) is located on a stream over which Congress has Commerce Clause jurisdiction, is constructed or modified on or after August 26, 1935, and affects the interests of interstate or foreign commerce.

The fourth prong itself has three main elements: project located on a Commerce Clause stream, post-1935 construction or modification, affecting interstate commerce. In this case, FERC concluded that the Egnaczak project satisfied the fourth prong.

First, FERC found that the Egnaczak project is located on a Commerce Clause stream. Under a 1965 Supreme Court ruling, for purposes of Federal Power Act section 23(b)(1), Commerce Clause streams are the headwaters and tributaries of navigable waters of the United States. While FERC declined to determine whether the Hoosic River is navigable at the site of the project, it concluded that downstream segments of the Hoosic are navigable, as is the Hudson River into which the Hoosic flows.

Second, FERC next found that installing new hydroelectric generating capacity constitutes post-1935 construction within the meaning of Federal Power Act section 23(b)(1).

Third, FERC found that the project would offset both electrical and heating needs that would have been otherwise supplied by the interstate grid -- and thus that the project would affect the interests of interstate commerce. A footnote notes, "It is well settled that small hydroelectric projects that are connected to the interstate grid affect interstate commerce by displacing power from the grid, and the cumulative effect of the national class of these small projects is significant for purposes of FPA section 23(b)(1)."

FERC concluded that because the project would be located on a Commerce Clause stream, would be constructed after 1935, and would affect interstate commerce through its connection to the interstate grid, Section 23(b)(1) of the Federal Power Act requires Kenneth and Susan Egnaczak to obtain a license for the project's construction, maintenance, and operation. The FERC order also suggests the project may be eligible to obtain an exemption from licensing as a small hydroelectric power project of 10 megawatts or less, and encourages the applicants to investigate the requirements for securing an exemption from licensure.

Panelists and audience members discussed some of the recent and ongoing solar energy policy discussions and outcomes in Maine, including a stakeholder process before the Maine Public Utilities Commission to explore an alternative policy complementary to net metering. That process is expected to wrap up this winter with a report to the legislative committee with jurisdiction over energy matters.

The event also featured Preti Flaherty's launch of its First Light initiative. Grounded in the Preti team’s
experience helping consumers benefit from distributed or “behind the meter” generation,
the firm has created a special focus on the commercialization of solar power by and for
all consumers. This strategic initiative will help qualified new entrants, as well as
larger, existing companies, navigate legal and business challenges to harness the power of
the sun. It will also help site owners
participate in solar energy as project hosts, through site leasing
and power purchase agreements or other arrangements. Contact Todd Griset for more information about qualifying for the Preti First Light program.

Most non-federal hydropower projects in the U.S. must be licensed by the Federal Energy Regulatory Commission. Under section 23(b)(1) of the Federal Power Act, a non-federal hydroelectric project without a still-valid pre-1920 federal permit must be licensed if it:

(a) is located on a navigable water of the United States;(b) occupies lands or reservations of the United States;(c) utilizes surplus water or waterpower from a government dam; or(d) is located on a stream over which Congress has Commerce Clause jurisdiction, is constructed or modified on or after August 26, 1935, and affects the interests of interstate or foreign commerce.

Part of the Hidden Falls Lake project -- the intake, penstock, 250-kW hydroelectric generator, powerhouse, and distribution lines -- are located on U.S. Forest Service lands. The Forest Service’s documentation states that a minor license application for the Hidden Falls Lake Project was filed with the Commission in 1981, but the Commission said it did not have any records of this application or of any subsequent Commission jurisdictional determination for this project.

But FERC did apparently know about the project. In 1989, seven years after the project's generator was installed, the Commission initiated an investigation into the jurisdictional status of the project, suggesting it was "unlicensed" or "unauthorized." Yet that unlicensed hydropower project investigation docket then went dormant until 2015. Last year, the Forest Service informed the Commission that it had identified the project while conducting environmental reviews in support of a renewal of the Alaska agency's special use permit for the hatchery. Thus the investigation resumed.

The Commission issued its final order in the case on January 28, 2016. Because the project intake, penstock, hydroelectric generator, powerhouse, and distribution lines occupy public lands of the United States, the Commission concluded that the Alaska agency must obtain a license for construction, maintenance, and continued operation of the Hidden Falls Lake Project. The Commission ordered the Alaska agency to file within 90 days a schedule for submitting a license application within 36 months.

If a small hydropower project on a remote Alaskan island is subject to FERC licensure, how many other unlicensed hydropower projects might be out there? How many other unlicensed hydropower projects might there be on Forest Service or other federal lands? While FERC investigations of unlicensed hydropower projects are relatively rare, with most years seeing only a handful of public active investigations, could there be other existing projects like the Hidden Falls Lake Project?

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About this blog

A blog about energy resources, energy policy, and their effects on society and the environment. From fossil fuels to renewable energy, electricity to natural gas and oil, traditional technologies to innovations, this blog presents a look at the past, present, and future of energy.

This blog site is published by and reflects the personal views of Todd Griset, in his individual capacity. It does not necessarily represent the views of his law firm or clients, and is not sponsored or endorsed by them. The purpose of this blog site is to assist in dissemination of information about energy policy and related issues, but no representation is made about the accuracy of the information. The information contained in this blog site is provided only as general information for education purposes, and blog topics may or may not be updated subsequent to their initial posting.

By using this blog site you understand that this information is not provided in the course of an attorney-client relationship and is not intended to constitute legal advice. This blog site should not be used as a substitute for competent legal advice from a licensed attorney in your state. This blog site is not intended to be advertising and Todd Griset does not wish to represent anyone desiring representation based upon viewing this blog site in a state where this blog site fails to comply with all laws and ethical rules of that state.